DENBURY RESOURCES INC

Transcription

1 DENBURY RESOURCES INC FORM 10-K (Annual Report) Filed 02/28/13 for the Period Ending 12/31/12 Address 5320 LEGACY DRIVE PLANO, TX Telephone CIK Symbol DNR SIC Code Crude Petroleum and Natural Gas Industry Oil & Gas Operations Sector Energy Fiscal Year 12/31 Copyright 2013, EDGAR Online, Inc. All Rights Reserved. Distribution and use of this document restricted under EDGAR Online, Inc. Terms of Use.

2 UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C FORM 10-K (Mark One) Annual report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the fiscal year ended December 31, 2012 OR Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the transition period from to Commission file number DENBURY RESOURCES INC. (Exact name of Registrant as specified in its charter) Delaware (State or other jurisdiction of incorporation or organization) (I.R.S. Employer Identification No.) 5320 Legacy Drive, Plano, TX (Address of principal executive offices) (Zip Code) Registrant s telephone number, including area code: (972) Securities registered pursuant to Section 12(b) of the Act: Title of Each Class: Common Stock $.001 Par Value Name of Each Exchange on Which Registered: New York Stock Exchange Securities registered pursuant to Section 12(g) of the Act: None Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes No Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes No Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes No Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes No Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a small reporting company. See definition of large accelerated filer, accelerated filer, and small reporting company in Rule 12-b2 of the Exchange Act. Large accelerated filer Accelerated filer Non-accelerated filer Smaller reporting company Indicate by check mark whether the registrant is a shell company (as defined in Exchange Act Rule 12b-2). Yes No The aggregate market value of the registrant s common stock held by non-affiliates, based on the closing price of the registrant s common stock as of the last business day of the registrant s most recently completed second fiscal quarter was $5,050,462,439. The number of shares outstanding of the registrant s Common Stock as of January 31, 2013, was 373,462,597. Document: DOCUMENTS INCORPORATED BY REFERENCE Incorporated as to: 1. Notice and Proxy Statement for the Annual Meeting of Stockholders to be held May 22, Part III, Items 10, 11, 12, 13, 14

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4 2012 Annual Report on Form 10-K Page Glossary and Selected Abbreviations 3 PART I Item 1. Business and Properties 5 Item 1A. Risk Factors 27 Item 1B. Unresolved Staff Comments 34 Item 2. Properties 34 Item 3. Legal Proceedings 34 Item 4. Mine Safety Disclosures 34 PART II Item 5. Market for Registrant s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 35 Item 6. Selected Financial Data 37 Item 7. Management s Discussion and Analysis of Financial Condition and Results of Operations 39 Item 7A. Quantitative and Qualitative Disclosures About Market Risk 65 Item 8. Financial Statements and Supplementary Data 65 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 113 Item 9A. Controls and Procedures 113 Item 9B. Other Information 113 PART III Item 10. Directors, Executive Officers and Corporate Governance 114 Item 11. Executive Compensation 114 Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 114 Item 13. Certain Relationships and Related Transactions, and Director Independence 114 Item 14. Principal Accountant Fees and Services 114 PART IV Item 15. Exhibits and Financial Statement Schedules 115 Signatures

5 Glossary and Selected Abbreviations Bbl Bbls/d Bcf Bcfe BOE BOE/d One stock tank barrel, of 42 U.S. gallons liquid volume, used herein in reference to crude oil or other liquid hydrocarbons. Barrels of oil produced per day. One billion cubic feet of natural gas, CO 2 or helium. One billion cubic feet of natural gas equivalent, using the ratio of one barrel of crude oil, condensate or natural gas liquids to 6 Mcf of natural gas. One barrel of oil equivalent, using the ratio of one barrel of crude oil, condensate or natural gas liquids to 6 Mcf of natural gas. BOEs produced per day. Btu British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit. CO 2 EOR Finding and Development Costs MBbls MBOE Mbtu Mcf Mcf/d MMBbls MMBOE MMBtu MMcf MMcf/d Probable Reserves* Carbon dioxide. Enhanced oil recovery. The average cost per BOE to find and develop proved reserves during a given period. It is calculated by dividing costs, which includes the total acquisition, exploration and development costs incurred during the period plus future development and abandonment costs related to the specified property or group of properties, by the sum of (i) the change in total proved reserves during the period plus (ii) total production during that period. One thousand barrels of crude oil or other liquid hydrocarbons. One thousand BOEs. One thousand Btus. One thousand cubic feet of natural gas, CO 2 or helium at a temperature base of 60 degrees Fahrenheit ( F) and at the legal pressure base (14.65 to pounds per square inch absolute) of the state or area in which the reserves are located or sales are made. One thousand cubic feet of natural gas, CO 2 or helium produced per day. One million barrels of crude oil or other liquid hydrocarbons. One million BOEs. One million Btus. One million cubic feet of natural gas, CO 2 or helium. One million cubic feet of natural gas, CO 2 or helium per day. Are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

6 Proved Developed Reserves* Proved Reserves* Proved Undeveloped Reserves* Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. The estimated quantities of reserves that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required

7 PV-10 Value When used with respect to oil and natural gas reserves, PV-10 Value means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated future production, development and abandonment costs, and before income taxes, discounted to a present value using an annual discount rate of 10%. PV-10 Values were prepared using average hydrocarbon prices equal to the unweighted arithmetic average of hydrocarbon prices on the first day of each month within the 12-month period preceding the reporting date. PV-10 Value is a non-gaap measure and its use is further discussed in footnote 4 to the table included in Item 1, Estimated Net Quantities of Proved Oil and Natural Gas Reserves and Present Value of Estimated Future Net Revenues - Oil and Natural Gas Reserve Estimates. Tcf One trillion cubic feet of natural gas, CO 2 or helium. * This definition is an abbreviated version of the complete definition as defined by the SEC in Rule 4-10(a) of Regulation S-X. For the complete definition see:

8 PART I Item 1. Business and Properties GENERAL, a Delaware corporation, is a domestic independent oil and natural gas company with MMBOE of estimated proved oil and natural gas reserves as of December 31, 2012, of which 80% is oil. Our primary focus is on enhanced oil recovery utilizing CO 2, and our operations are focused in two key operating areas: the Gulf Coast region and Rocky Mountain region. We are the largest combined oil and natural gas producer in both Mississippi and Montana, and we own the largest reserves of CO 2 used for tertiary oil recovery east of the Mississippi River. Our goal is to increase the value of acquired properties through a combination of exploitation, drilling and proven engineering extraction practices, with the most significant emphasis relating to tertiary recovery operations. As part of our corporate strategy, we believe in the following fundamental principles: focus in specific regions where we either have, or believe we can create, a competitive advantage as a result of our ownership or use of CO 2 reserves, oil fields and CO 2 infrastructure; acquire properties where we believe additional value can be created through tertiary recovery operations and a combination of other exploitation, development, exploration and marketing techniques; acquire properties that give us a majority working interest and operational control or where we believe we can ultimately obtain it; maximize the value of our properties by increasing production and reserves while controlling cost; and maintain a highly competitive team of experienced and incentivized personnel. Denbury became a Canadian public company in In 1999, we moved our corporate domicile from Canada to the United States as a Delaware corporation and have been publicly traded in the United States since 1995 and on the New York Stock Exchange since May Our corporate headquarters is located at 5320 Legacy Drive, Plano, Texas 75024, and our phone number is At December 31, 2012, we had 1,432 employees, 766 of whom were employed in field operations or at our field offices. We make our annual report on Form 10- K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports, filed or furnished pursuant to section 13(a) or 15(d) of the Securities Exchange Act of 1934, available free of charge on or through our Internet website, as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. The SEC also maintains a website, which contains reports, proxy and information statements and other information filed by Denbury. Throughout this Annual Report on Form 10-K ("Form 10-K") we use the terms Denbury, Company, we, our, and us to refer to and, as the context may require, its subsidiaries BUSINESS DEVELOPMENTS Increased our average tertiary oil production to 35,206 Bbls/d in 2012, a 14% increase from average tertiary production in 2011 due to contributions from our newest CO 2 floods at Oyster Bayou and Hastings fields and expansion of our existing CO 2 floods at Tinsley, Heidelberg and Delhi fields. Added estimated proved tertiary reserves of 69.5 MMBbls, primarily including initial tertiary reserve bookings of 42.6 MMBbls at Hastings Field and 14.1 MMBbls at Oyster Bayou Field. The combined PV-10 value of the proved tertiary reserves at Hastings and Oyster Bayou fields at December 31, 2012 was $1.7 billion. Completed construction of the first section of the Greencore pipeline, our first CO 2 pipeline in the Rocky Mountain region, which is on schedule to begin deliveries of CO 2 from the Lost Cabin gas plant to our Bell Creek Field in Montana in the first half of Continued our share repurchase program, under which we repurchased a total of 17.0 million shares of Denbury common stock for $266.7 million during 2012, in addition to 14.1 million shares of Denbury common stock repurchased in 2011 for - 5 -

9 $195.2 million. As of February 21, 2013, we had spent a total of $521.0 million to repurchase an aggregate of 34.6 million shares, or approximately 8.6% of our outstanding shares as of September 30, 2011, at an average cost of $15.05 per share. Completed or entered into agreements on several strategic and tax efficient property transactions which not only add value, but as importantly, make us a nearly pure CO 2 EOR company. These asset transactions, which included both acquisitions and dispositions, aggregated (or upon completion will aggregate) over $4 billion in value, and (1) resulted in an increase in our unproven potential reserves, which we believe provides us a better opportunity to achieve a higher return due to the nature of the acquired properties compared to the sold properties, (2) nearly replaced the production of the sold assets with that from the acquired or to-be-acquired assets, (3) exchanged proved reserves with a high proved undeveloped component for reserves that are nearly all proved developed, which significantly increases our current free cash flow, (4) increased our Rocky Mountain CO 2 reserves by 1.3 Tcf and up to 115 MMcf/d of deliverability, and (5) positioned us to execute on our long-term strategy which we expect will increase shareholder value for many years to come. A summary of these transactions follows, with more detail on each significant transaction discussed further below: Bakken Exchange Transaction Divested our Bakken area assets, which were all non-tertiary, at an estimated value of approximately $2.0 billion, in exchange for interests in two future potential tertiary oil fields, a new Rocky Mountain region CO 2 source and $1.3 billion of cash. Pending Cedar Creek Anticline Acquisition Entered into an agreement in early 2013 to purchase additional interests in the Cedar Creek Anticline ("CCA") in Montana and North Dakota (the "Pending CCA Acquisition"), an area with future potential tertiary oil upside, for $1.05 billion, which will be funded with a portion of the cash proceeds from the Bakken Exchange Transaction. We expect to complete the Pending CCA Acquisition near the end of the first quarter of In two separate transactions earlier in 2012, which were also structured as like-kind exchanges for federal income tax purposes, we completed the following: Acquisition of Thompson Field Acquired a nearly 100% working interest and 84.7% net revenue interest in the Thompson Field in south Texas, a future potential tertiary oil field approximately 18 miles from our current EOR flood at Hastings Field, for $366.2 million. Sale of Non-core Assets Sold our interests in non-core oil and natural gas fields in the Paradox Basin of Utah and in the Gulf Coast region for $68.5 million and $141.8 million, respectively. Bakken Exchange Transaction. In late 2012, we closed a sale and exchange transaction with Exxon Mobil Corporation and its whollyowned subsidiary XTO Energy Inc. (collectively, ExxonMobil ) under which we sold to ExxonMobil our Bakken area assets in North Dakota and Montana in exchange for $1.3 billion in cash (after preliminary closing adjustments) and EOR assets (the Bakken Exchange Transaction ). By exchanging these non-tertiary Bakken area assets for EOR assets, we are able to more purely focus our attention on tertiary recovery operations. The Bakken area assets we sold had proved reserves of approximately 109 MMBOE at the time of sale, of which 66% was undeveloped, and 2012 production through the third quarter of 15,850 BOE/d. The EOR assets acquired in the Bakken Exchange Transaction include: (1) Webster Field, a planned future tertiary field, located in southeastern Texas, with nearly 100% working interest and 80% net revenue interest, proved reserves of 3.7 MMBOE and production of approximately 1,000 BOE/d; (2) Hartzog Draw Field, a planned future tertiary field located in Wyoming, consisting of an 83% working interest and 71% net revenue interest in the oil-producing Shannon Sandstone zone and a 67% working interest and 53% net revenue interest in the natural gas-producing Big George Coal zone, with proved reserves of 5.2 MMBOE and production of approximately 2,600 BOE/d; and (3) approximately a one-third overriding royalty ownership interest in ExxonMobil's CO 2 reserves in LaBarge Field in Wyoming with proved reserves of 1.3 Tcf and estimated deliverability of up to 115 MMcf/d. Pending CCA Acquisition. In January 2013, we entered into an agreement to acquire producing assets in the CCA of Montana and North Dakota from a wholly-owned subsidiary of ConocoPhillips for $1.05 billion in cash, before standard closing adjustments primarily for revenues and costs of the properties to be purchased from the January 1, 2013 effective date to the closing date. We plan to fund the acquisition with a portion of the cash proceeds from the Bakken Exchange Transaction in order to qualify the acquisition for like-kind-exchange treatment under federal income tax rules. We expect the Pending CCA Acquisition to close near the end of the first quarter of

10 The assets we plan to purchase from ConocoPhillips include both additional interests in certain of our existing operated fields in CCA as well as operating interests in other CCA fields. We currently estimate on a preliminary basis that, as of December 31, 2012, the proved conventional (non-tertiary) reserves associated with the acquired assets, net to our acquired interests, were approximately 42 MMBOE, of which approximately 99% is oil and natural gas liquids, with average daily production of approximately 11,000 BOE/d during the fourth quarter of We plan to incorporate the newly acquired CCA assets into our CO 2 development plan that is currently being designed and to extend the Greencore pipeline north and southwest in order to deliver the CO 2 necessary to flood the CCA assets. Acquisition of Thompson Field. In June 2012, we acquired a nearly 100% working interest and 84.7% net revenue interest in Thompson Field for $366.2 million after preliminary closing adjustments. The field is located approximately 18 miles west of our Hastings Field, which we are currently flooding with CO 2, and which is the current terminus of the Green Pipeline which transports CO 2 from natural sources in the Jackson Dome area of Mississippi. Thompson Field is similar to Hastings Field, producing oil from the Frio zone at similar depths, and is a planned future tertiary field. Sale of Non-Core Assets. On April 9, 2012, we completed the sale of certain non-operated assets in the Paradox Basin of Utah for $68.5 million cash after final closing adjustments. On February 29, 2012, we completed the sale of certain non-core assets primarily located in central and southern Mississippi and in southern Louisiana for $141.8 million, after final closing adjustments. We structured the sale of our non-core assets and the purchase of Thompson Field as a like-kind-exchange transaction for federal income tax purposes and anticipate deferral of a majority of the taxable gain recognized on the sale of the non-core assets ENCORE ACQUISITION AND RELATED DISPOSITIONS On March 9, 2010, we acquired Encore Acquisition Company ( Encore ) pursuant to an Agreement and Plan of Merger (the "Encore Merger Agreement") in a stock and cash transaction valued at approximately $4.8 billion at the acquisition date, including the assumption of Encore debt and the value of the non-controlling interest in Encore Energy Partners LP ( ENP ). Under the Encore Merger Agreement, Encore was merged with and into Denbury (the Encore Merger ), with Denbury surviving the Encore Merger. Pursuant to our stated intent, at the time of acquisition, to divest certain non-strategic legacy Encore properties, certain oil and gas properties in the Permian Basin, Mid-continent area and East Texas Basin were sold in May We subsequently divested our production and acreage in the Cleveland Sand Play and Haynesville Play during 2010 as well. In addition to the property sales, we sold our ownership interests in ENP on December 31, Collectively, we received approximately $1.5 billion in total consideration from these divestitures in 2010, excluding the bank debt of ENP that was assumed by the purchaser in the sale. In 2012, we exchanged the Bakken area assets acquired in the Encore Merger for cash and other assets with an estimated value of approximately $2.0 billion (see 2012 Business Developments Bakken Exchange Transaction above). OIL AND NATURAL GAS OPERATIONS Summary. Our oil and natural gas properties are concentrated in the Gulf Coast and Rocky Mountain regions of the United States. Currently our properties with proved and producing reserves in the Gulf Coast region are situated in Mississippi, Texas, Louisiana and Alabama, and in the Rocky Mountain region in Montana, North Dakota and Wyoming. Our primary focus is using CO 2 in EOR, which we have been doing since we acquired Little Creek Field in the Gulf Coast region in EOR, which we also refer to as tertiary recovery (as opposed to primary and secondary recovery), is a term used to represent techniques for extracting incremental oil out of existing oil fields. We acquired Encore during 2010 with the intent to employ our tertiary recovery strategy using CO 2 in the Rocky Mountain region. Our current portfolio of properties provides us significant growth potential for more than a decade. Our Gulf Coast EOR operations are driven by CO 2 produced from natural sources in the Jackson Dome area of Mississippi, which is transported to our Gulf Coast tertiary fields. In late 2012, we received first deliveries of anthropogenic (man-made) CO 2 into the Gulf Coast pipeline system from an industrial facility in Port Arthur, Texas. The CO 2 for our Rocky Mountain EOR operations will initially be supplied from the Lost Cabin gas plant in Wyoming and from an overriding royalty interest equivalent to an approximate one-third ownership interest in ExxonMobil's CO 2 reserves in LaBarge Field, which overriding royalty interest we acquired during 2012 in the Bakken Exchange Transaction. In the future, we intend to utilize CO 2 from our Riley Ridge CO 2 source. In 2012, we completed the initial 232-mile segment of the 20-inch Greencore Pipeline, which will serve as part of the planned CO 2 trunk line in the region. Although our development of tertiary fields, CO 2 sources and pipelines in the Rocky Mountain - 7 -

11 region is just beginning, we believe that our significant CO 2 sources and planned pipeline infrastructure in the area will allow us to utilize CO 2 injection to potentially recover significant amounts of incremental oil from mature oil fields. Each of our significant development areas and planned activities is discussed in more detail below. The following table provides a summary by field and region of selected proved oil and natural gas reserve information, including total proved reserve quantities and the associated PV-10 Value of those reserves as of December 31, 2012, and average daily production and net revenue interest ( NRI ) for The reserve estimates for all years presented were prepared by DeGolyer and MacNaughton, independent petroleum engineers located in Dallas, Texas. We serve as operator of virtually all of our significant properties, in which we also own most of the interests, although typically less than a 100% working interest, and a lesser net revenue interest due to royalties and other burdens. For additional reserve information, see Estimated Net Quantities of Proved Oil and Natural Gas Reserves and Present Value of Estimated Future Net Revenues below. Tertiary oil properties Gulf Coast region Mature properties: Oil (MBbls) Proved Reserves as of December 31, 2012 (1) Natural Gas (MMcf) MBOEs BOE % of total PV-10 Value (2) (000's) 2012 Average Daily Production Oil (Bbls/d) Natural Gas (Mcf/d) Average 2012 NRI Brookhaven 10,938 10, % 467,653 2, % Eucutta 9,251 9, % 356,000 2, % Mallalieu 6,450 6, % 222,586 2, % Other mature properties (3) 27,343 27, % 865,308 7, % Delhi 25,038 25, % 989,608 4, % Hastings 45,261 45, % 1,179,241 2, % Heidelberg 34,599 34, % 1,156,508 3, % Oyster Bayou 13,602 13, % 496,501 1, % Tinsley 28,430 28, % 1,085,180 7, % Total tertiary oil properties 200, , % 6,818,585 35, % Non-tertiary oil and gas properties Gulf Coast region Mississippi 6,408 28,165 11, % 260,235 1,985 11, % Texas 33,694 17,861 36, % 1,035,953 4,157 3, % Other 7,070 1,599 7, % 180,805 1, % Total Gulf Coast region 47,172 47,625 55, % 1,476,993 7,229 16, % Rocky Mountain region Cedar Creek Anticline (4) 66, , % 1,267,881 8, % Riley Ridge (5) 2 416,281 69, % % Other 14,246 17,310 17, % 346,111 2,990 1, % Total Rocky Mountain region 81, , , % 1,614,014 11,432 1, % Total continuing properties 329, , , % 9,909,592 53,867 17, % Properties disposed in 2012 Bakken area assets % 12,539 11,140 Gulf Coast assets % Paradox assets % Total % 12,970 11,266 Company Total 329, , , % 9,909,592 66,837 29,109 (1) The reserves were prepared in accordance with Financial Accounting Standards Board Codification ("FASC") Topic 932, Extractive Industries Oil and Gas, using the average first-day-of-the-month prices for each month during 2012, which for - 8 -

12 NYMEX oil was $94.71 per Bbl, adjusted to prices received by field, and for natural gas was a Henry Hub cash price of $2.85 per MMBtu, also adjusted to prices received by field. (2) PV-10 Value is a non-gaap measure and is different from the Standardized Measure of Discounted Future Net Cash Flows ("Standardized Measure") in that PV-10 Value is a pre-tax number and the Standardized Measure is an after-tax number. The Standardized Measure was $6.4 billion at December 31, A comparison of PV-10 Value to the Standardized Measure is included in the reserves table in Estimated Net Quantities of Proved Oil and Natural Gas Reserves and Present Value of Estimated Future Net Revenues below. The information used to calculate PV-10 Value is derived directly from data determined in accordance with FASC Topic 932. See the definition of PV-10 Value in the Glossary and Selected Abbreviations. (3) Other mature properties include Cranfield, Little Creek, Lockhart Crossing, Martinville, McComb and Soso fields. (4) The Cedar Creek Anticline consists of a series of 10 producing oil units, each of which could be considered a field by itself. CCA reserves at December 31, 2012 do not include 42 MMBOE of currently estimated proved reserves we plan to acquire during the first quarter of 2013 through the Pending CCA Acquisition discussed above. See 2012 Business Developments Pending CCA Acquisition. (5) While the Riley Ridge Field reserves make up over 15% of the Company's total reserves, production from the field is currently negligible. We expect production to increase with the startup of the Riley Ridge gas plant in mid Enhanced Oil Recovery Overview. CO 2 used in EOR is one of the most efficient tertiary recovery mechanisms for producing crude oil. The CO 2 acts somewhat like a solvent, mixing with the oil and ultimately freeing the oil from the formation as the CO 2 passes through reservoir rock. CO 2 tertiary floods are unique in that they require large volumes of CO 2. To our knowledge, the location of large quantities of naturally occurring CO 2 in the United States is limited to a few geological basins. While enhanced oil recovery projects utilizing CO 2 may not be considered a new technology, we apply several concepts we have learned over the years to fields to improve and increase sweep efficiency within the reservoirs, which include: (1) well evaluation and monitoring methods, (2) CO 2 injection conformance, (3) new completion techniques, (4) varied operating equipment and operating conditions, and (5) application of intense reservoir management and production techniques. We began our CO 2 operations in August 1999, when we acquired Little Creek Field, followed by our acquisition of Jackson Dome CO 2 reserves and the NEJD pipeline in Based upon our success at Little Creek and the ownership of the CO 2 reserves, we began to transition our capital spending and acquisition efforts to focus a greater percentage on CO 2 EOR and, over time, transformed our strategy to focus primarily, and then almost exclusively, on CO 2 EOR projects. With the sale of our Bakken area assets in late 2012, our asset base today almost entirely relates to current or planned tertiary oil operations. We believe our investments, experience and acquired knowledge give us a strategic and competitive advantage in the areas in which we operate. Our tertiary operations have grown so that (1) 49% of our proved reserves at December 31, 2012 are proved tertiary oil reserves; (2) approximately 54% of our forecasted 2013 production is expected to come from tertiary oil operations (on a BOE basis); and (3) approximately 85% of our 2013 planned capital expenditures are related to our tertiary oil operations. At year-end 2012, the proved oil reserves in our tertiary recovery oil fields had an estimated PV-10 Value of approximately $6.8 billion, using 12-month first-day-of-the-month unweighted average NYMEX pricing during calendar 2012 of $94.71 per Bbl. In addition, there are significant probable and possible reserves at several other fields for which tertiary operations are under way or planned. Although the up-front cost of infrastructure and time to construct such is greater than in conventional oil recovery, we believe tertiary recovery has several favorable, offsetting and unique attributes including: (1) it has a lower risk, as we are operating oil fields that have significant historical production and reservoir and geological data, (2) our investments provide a reasonable rate of return at relatively low oil prices (we estimate our economic break-even point on a per-barrel basis before corporate-related overhead and expenses on our Gulf Coast projects at current oil prices is in the $40-per-barrel range, depending on the specific field and area), (3) we have limited competition for this type of activity in our geographic regions, and (4) our EOR activities could be considered more eco-friendly than other current oil and gas development, as we develop existing oil fields thereby not disturbing new habitats, drill fewer new wellbores, do not utilize hydraulic fracturing in our oil and natural gas development operations, and have the ability to geologically store CO 2 captured from industrial facilities. We have been conducting and expanding EOR operations on our assets in the Gulf Coast region since 1999, and as a result, they are more developed from an EOR perspective than our assets in the Rocky Mountain region. In the Gulf Coast region, we - 9 -

13 own what is, to our knowledge, the only significant naturally occurring source of CO 2, and these large volumes of CO 2 have allowed us to significantly grow our production in that region. In addition to the sources of CO 2 we currently own, we are pursuing anthropogenic (man-made) sources of CO 2 to use in our tertiary operations, which we believe will not only help us recover additional oil, but will also provide an economical and eco-friendly way to store CO 2. We started receiving our first anthropogenic CO 2 in the fourth quarter of 2012 from an industrial facility in Port Arthur, Texas and expect the amount of CO 2 we use in our operations coming from anthropogenic sources to grow in the future. Through December 31, 2012, we have invested a total of $3.0 billion in tertiary fields in our Gulf Coast region (including allocated acquisition costs and amounts assigned to goodwill) and have recovered all of these costs, with excess net cash flow (revenue less operating expenses and capital expenditures, excluding pipeline-related capital expenditures) of $1.1 billion. Of this total invested amount, approximately $185 million (6%) was spent on fields that did not yet have any appreciable proved reserves at December 31, The proved oil reserves in our Gulf Coast tertiary oil fields have a year-end 2012 PV-10 Value of $6.8 billion, using the 12-month first-day-of-the-month unweighted average NYMEX pricing during calendar 2012 of $94.71 per Bbl. These amounts do not include the capital costs or related depreciation and amortization of our CO 2 -producing properties or CO 2 pipelines, but do include CO 2 source field lease operating and transportation costs. Including the Green Pipeline, which currently services our Hastings and Oyster Bayou fields, we have invested a total of $2.0 billion in CO 2 -producing assets and pipelines in the Gulf Coast region. We began operations in the Rocky Mountain region in March 2010 as part of the Encore Merger, and as such, we have significantly fewer oil fields and less CO 2 pipeline infrastructure in that region, although we are aggressively developing both. We currently have four properties in the Rocky Mountain region that we plan to flood with CO 2 : Bell Creek Field, Grieve Field, Hartzog Draw Field, and Cedar Creek Anticline. The Cedar Creek Anticline is a geological structure over 126 miles in length consisting of 10 different operating units. We have contracted to purchase CO 2 from the Lost Cabin gas plant in central Wyoming and completed construction of the first section of the Greencore Pipeline in late 2012 to deliver CO 2 from such gas plant to our Bell Creek Field. We currently expect to begin purchasing CO 2 from the Lost Cabin plant during the first quarter of 2013 and start injections at Bell Creek Field during the second quarter of Our Riley Ridge acquisitions in 2010 and 2011 and ExxonMobil CO 2 acquisition in 2012 provide us additional sources of CO 2 for our currently planned and future potential projects in the area. Tertiary Oil Properties Gulf Coast Region CO 2 Sources and Pipelines Jackson Dome. Our primary Gulf Coast CO 2 source, Jackson Dome, located near Jackson, Mississippi, was discovered during the 1970s while being explored for hydrocarbons. This significant and relatively pure source of CO 2 (98% CO 2 ) is, to our knowledge, the only significant deposit of CO 2 in the United States east of the Mississippi River, and we believe that it provides us a significant strategic advantage in the acquisition of other properties in Mississippi, Louisiana and Texas that could be further exploited through tertiary recovery. We acquired Jackson Dome in February 2001 for $42 million, a purchase that also gave us ownership and control of the NEJD CO 2 pipeline. This acquisition provided the platform to significantly expand our CO 2 tertiary recovery operations by assuring that CO 2 would be available to us on a reliable basis and at a reasonable and predictable cost. Since February 2001, we have acquired and drilled numerous CO 2 - producing wells, significantly increasing our estimated proved Gulf Coast CO 2 reserves from approximately 800 Bcf at the time of acquisition to approximately 6.1 Tcf as of December 31, The CO 2 reserve estimates are based on a gross working interest of the CO 2 reserves, of which our net revenue interest is approximately 4.8 Tcf and is included in the evaluation of proved CO 2 reserves prepared by our outside reserve engineer, DeGolyer and MacNaughton. In discussing our available CO 2 reserves, we make reference to the gross amount of proved and probable reserves, as this is the amount that is available both for our own tertiary recovery programs and for industrial users who are customers of Denbury and others, as we are responsible for distributing the entire CO 2 production stream. In addition to the proved reserves, we estimate that we have 2.4 Tcf of probable CO 2 reserves at Jackson Dome, and significant other possible reserves. The majority of our probable reserves at Jackson Dome are located in structures that have been drilled

14 and tested in the area but are not currently capable of producing because (1) the original well is plugged; (2) they are located in fault blocks that are immediately adjacent to fault blocks with proved reserves; (3) they are in undrilled structures where we have sufficient subsurface data, and seismic and geophysical attributes that provide a high degree of certainty that CO 2 is present; or (4) they are reserves associated with increasing the ultimate recovery factor from our existing reservoirs with proved reserves. Our historically high drilling success rate, coupled with our seismic data across the undrilled structures, provide us with a reasonably high degree of certainty that additional CO 2 reserves will be developed. Although our current proved CO 2 reserves are quite large, in order to continue our tertiary development of oil fields in the Gulf Coast region, incremental deliverability of CO 2 is required. In order to obtain additional CO 2 deliverability, we have conducted several 3D seismic surveys in the area over the past several years, and anticipate drilling five development wells in 2013 that are intended to increase productive capacity, three of which could potentially add incremental CO 2 reserves. In addition to our drilling at Jackson Dome, we continue to expand our processing and dehydration capacities, and we continue to install pipelines and/or pumping stations necessary to transport the CO 2 through our controlled pipeline network. We expect our current proved reserves of CO 2, coupled with a risked drilling program at Jackson Dome and expected anthropogenic sources, to provide more than enough CO 2 for our existing and currently planned phases of operations in the Gulf Coast, including several fields we own and plan to flood that do not have proven tertiary reserves. Additionally, in the future, we believe that once a CO 2 flood reaches its productive economic limit, we could recycle a portion of the CO 2 that remains in that reservoir and utilize it in another tertiary flood. In addition to using CO 2 for our Gulf Coast tertiary operations, we sell CO 2 to third-party industrial users under long-term contracts and currently have three CO 2 volumetric production payment contracts. Approximately 91% of our average daily CO 2 production in 2012 and 2011 and 87% in 2010 was used in our tertiary recovery operations on our own behalf and on behalf of other working interest owners and royalty owners in our enhanced recovery fields, with the balance delivered to third-party industrial users. During 2012, we sold an average of 92 MMcf/d of CO 2 to commercial users, and we used an average of 933 MMcf/d for our tertiary activities. We are continuing to increase our CO 2 production, which averaged 1,100 MMcf/d during the fourth quarter of 2012, a 7% increase over the fourth quarter of Gulf Coast Anthropogenic CO 2 Sources. In addition to our natural source of CO 2, we are currently party to five long-term contracts to purchase man-made CO 2 from five plants that either exist, are currently under construction, or are planned, in the Gulf Coast region. In late 2012, we received first deliveries of anthropogenic CO 2 into the Gulf Coast pipeline system from an industrial facility in Port Arthur, Texas, and we anticipate taking deliveries from another existing plant in 2013 and a plant currently under construction in early We estimate these three sources will supply approximately 200 MMcf/d of CO 2 to our EOR operations, although under certain circumstances they could provide higher volumes. If the remaining two plants as to which we have long-term CO 2 purchase contracts also were to be built, we currently estimate our anthropogenic CO 2 sources could potentially provide us with aggregate CO 2 volumes of up to 600 MMcf/d. Construction of these two plants is considered probable, although is contingent on the satisfactory resolution of various matters, including financing. While both of these plants may not be constructed, other plants currently being planned could provide us additional anthropogenic CO 2. We are in ongoing discussions with, and/or have entered into contractual arrangements to purchase CO 2 from, several of these other potential sources. In addition to potential CO 2 sources discussed above, we continue to have ongoing discussions with owners of existing plants of various types that emit CO 2 that we may be able to purchase and/or transport. In order to capture such volumes, we (or the plant owner) would need to install additional equipment, which includes, at a minimum, compression and dehydration facilities. Most of these existing plants emit relatively small volumes of CO 2, generally less than the proposed gasification plants, but such volumes may still be attractive if the source is located near CO 2 pipelines. The capture of CO 2 could also be influenced by potential federal legislation, which could impose economic penalties for the emission of CO 2. We believe that we are a likely purchaser of CO 2 captured in our areas of operation because of the scale of our tertiary operations, our CO 2 pipeline infrastructure and our large natural sources of CO 2, which can act as a swing CO 2 source to balance CO 2 supply and demand. Gulf Coast CO 2 Pipelines. We acquired the 183-mile NEJD CO 2 pipeline that runs from Jackson Dome to near Donaldsonville, Louisiana, as part of the 2001 acquisition of our Jackson Dome source. Since 2001 we have acquired or constructed nearly 750 miles of CO 2 pipelines, which give us the ability to deliver CO 2 throughout the Gulf Coast. As of December 31, 2012, we have access to over 920 miles of CO 2 pipelines in the Gulf Coast region. In addition to the NEJD CO 2 pipeline, the major pipelines are the Free State Pipeline (90 miles), the Delta Pipeline (110 miles) and the Green Pipeline (325 miles)

15 Completion of the Green Pipeline facilitated the first CO 2 injection into the Hastings Field, located near Houston, Texas, in late The completion of the Green Pipeline gives us the ability to deliver CO 2 to oil fields all along the Gulf Coast from Baton Rouge, Louisiana, to Alvin, Texas. At the present time, most of the CO 2 flowing in the Green Pipeline is delivered from the Jackson Dome are a, but we recently began receiving anthropogenic CO 2 from a plant in Port Arthur, Texas, and will transport a third party's CO 2 for a fee to the sales point at Hastings Field. We expect the volume of anthropogenic CO 2 flowing through the Green Pipeline to increase in future years. Tertiary Properties with Tertiary Production and Tertiary Reserves at December 31, 2012 Mature properties. Mature properties include several fields along our NEJD CO 2 pipeline and the Free State pipeline, which run through east Mississippi, southwest Mississippi and into Louisiana. This grouping includes some of our most mature CO 2 floods, including our initial CO 2 field, Little Creek, as well as several other areas (Brookhaven, Cranfield, Eucutta, Lockhart Crossing, Mallalieu, Martinville, McComb and Soso fields). These fields accounted for approximately 44% of our total 2012 CO 2 EOR production and 27% of our proved tertiary reserves. These fields have been producing for some time, and their production is generally on decline. Many of these fields contain multiple reservoirs that are amenable to CO 2 EOR. In 2013, we plan to invest approximately $90 million in our mature properties. Most of the development work is complete in this area; however, there are some additional areas at McComb, Cranfield, Brookhaven and Little Creek that we currently plan to develop. EOR operations in Eucutta and Martinville fields were initiated in 2006 following completion of the Free State Pipeline, and the fields are mostly developed in the reservoir(s) under flood at the present time. In addition to the developed reservoirs, these fields have potential development targets in other vertically segregated reservoirs. As these fields have matured, we have experimented with a variety of techniques to maximize the recovery of oil from these reservoirs, gathering knowledge that we will utilize in all areas of our EOR operations. All of the techniques we are employing are intended to improve the overall sweep efficiency in the formation and hence to maximize production. Due to the lower viscosity of CO 2 when compared to oil, CO 2 will tend to follow the path of least resistance. This may result in high producing gas-oil ratios sooner than anticipated. In order to address this issue, we have experimented with various techniques such as cement squeezes (injection and producing wells), chemical squeezes, perforation design, mechanical isolation assemblies and operating pressure controls. We have also utilized water-alternating gas injections, where water is substituted for the CO 2 for a given volume and then CO 2 is injected behind the water. Each one of these processes has had some success and we plan to continue to utilize them in the future as appropriate. From inception through December 31, 2012, we have recovered all our costs relating to our mature properties, and the excess net cash flow (revenue less operating expenses and capital expenditures, including the acquisition costs) from the mature properties was $1.7 billion. As of December 31, 2012, the estimated PV-10 Value of our mature properties was $1.9 billion. Delhi Field. Delhi Field is located southwest of Tinsley Field and east of Monroe, Louisiana. During May 2006, we purchased Delhi for $50 million, plus an approximate 25% reversionary interest to the seller after we achieve $200 million in net operating income. We began well and facility development in 2008 and began delivering CO 2 to the field in the fourth quarter of 2009 via the Delta Pipeline, which runs from Tinsley Field to Delhi Field. First tertiary production occurred at Delhi Field in March Current trend and performance data indicate that Delhi Field is acting as predicted and continues to provide a positive outlook for this field. Production from Delhi in the fourth quarter of 2012 averaged 5,237 Bbls/d, up from 3,778 Bbls/d in the year-ago period. In 2013, we plan to invest approximately $40 million to drill 15 wells and optimize existing development patterns at Delhi Field. Based on our current estimates, we expect the reversionary interest to come into effect some time in the latter part of 2013, which will reduce our net revenue interest in the field at that time. From inception through December 31, 2012, we had not yet recovered our investment in this field, and the remaining investment to be recovered (revenue less operating expenses and capital expenditures, including the acquisition costs) from Delhi Field was $122 million. As of December 31, 2012, the estimated PV-10 Value of Delhi Field was $989.6 million. Hastings Field. Hastings Field is located just south of Houston, Texas. We acquired a majority interest in this field in February 2009 for approximately $247 million. Due to the large vertical oil column that exists in the field, we are developing the Frio reservoir using dedicated CO 2 injection and producing wells for each of the major sand intervals. We initiated CO 2 injection in the West Hastings Unit during December 2010 upon completion of the construction of the Green Pipeline. We began producing

16 oil from our EOR operations at Hastings Field in January 2012, and we booked proved tertiary reserves of 42.6 MMBbl for the West Hastings Unit in During the fourth quarter of 2012, tertiary production from Hastings Field averaged 3,409 Bbls/d, compared to zero in the yearago period. In 2013, we plan to invest approximately $90 million to continue developing the West Hastings Unit, including the development of additional patterns and expansion of the processing facilities. Significant additional capital expenditures will be required over several years to fully develop the field. From inception through December 31, 2012, we had not yet recovered our investment in this field, and the remaining investment to be recovered (revenue less operating expenses and capital expenditures, including the acquisition cost) from Hastings Field was $331 million. As of December 31, 2012, the estimated PV-10 Value of Hastings Field was $1.2 billion. Heidelberg Field. In 2008, we began CO 2 injections at Heidelberg Field, which is located in Mississippi and consists of an East and West Unit. Construction of the CO 2 facility, connecting pipeline and well work commenced on the West Heidelberg Unit during 2008, with our first CO 2 injections beginning in December Our first tertiary oil production response occurred during May During 2010, we added injection patterns and expanded the central processing facility. Production from the West Unit began to decline in 2011 and we determined that CO 2 was not reaching all the targeted zones, broadly described as conformance issues. In 2011, we modified our development pattern to address the conformance issues by redirecting CO 2 into previously unswept intervals in the West Heidelberg Unit, and we believe this work has been successful. During the fourth quarter of 2012, tertiary production at Heidelberg Field averaged 3,930 Bbls/d, compared to 3,728 Bbls/d in the year-ago period. In 2012, we continued the development of our East Heidelberg Unit, which is larger and contains more oil in place than the West Heidelberg Unit, by initiating the second phase of the Eutaw development and the first phase of the Christmas development. In 2013, we plan to invest approximately $100 million to continue developing the East Heidelberg Unit, including an expansion of our development of the Eutaw and Christmas zones, and we plan to invest $20 million in the West Heidelberg Unit to optimize our development in the area. From inception through December 31, 2012, we have recovered all our costs relating to the CO 2 flood at Heidelberg Field, and the excess net cash flow (revenue less operating expenses and capital expenditures, including the acquisition costs) from the field was $51 million. As of December 31, 2012, the estimated PV-10 Value of Heidelberg Field was $1.2 billion. Oyster Bayou Field. Oyster Bayou Field, of which we acquired a majority interest in 2007, is located in southeast Texas on the east side of Galveston Bay. Oyster Bayou Field was unitized in the spring of 2010 and we began CO 2 injections there in June Oyster Bayou Field is somewhat unique when compared to our other CO 2 EOR projects because the field covers a relatively small area of 3,912 acres and was designed to be developed in essentially one stage. We commenced production from Oyster Bayou Field in December 2011 and booked initial proved tertiary reserves for the field of 14.1 MMBbl in During the fourth quarter of 2012, tertiary production at Oyster Bayou Field averaged 1,826 Bbls/d, compared to 18 Bbls/d in the year-ago period. In 2013, we plan to invest approximately $5 million to increase our CO 2 injection and water disposal capacity at Oyster Bayou Field. From inception through December 31, 2012, we had not yet recovered our investment in this field, and the remaining investment to be recovered (revenue less operating expenses and capital expenditures, including the acquisition costs) from Oyster Bayou Field was $165 million. As of December 31, 2012, the estimated PV-10 Value of Oyster Bayou Field was $ million. Tinsley Field. Tinsley Field was acquired in January 2006, is located in Mississippi, and was first developed in the 1930s. As is the case with the majority of fields in Mississippi, Tinsley produces from multiple reservoirs. Our primary target in Tinsley for CO 2 enhanced oil recovery operations is the Woodruff formation, although there is additional potential in the Perry sandstone and other smaller reservoirs. We initiated limited CO 2 injections in January 2007 through a previously existing 8-inch pipeline, but replaced the use of the 8-inch line in 2008 upon the completion of the 24-inch Delta Pipeline to Tinsley Field. We had our first tertiary oil production from Tinsley Field in April As of December 31, 2012, we have completed the development of the West and East Fault Blocks. In 2012, we installed and began injection into three patterns of the North Fault Block of Tinsley. We also installed trunklines and a test site to support future North Fault Block development. In 2013, we expect to invest approximately $40 million to continue our development of the North Fault Block at Tinsley Field. During the fourth quarter of 2012, the average tertiary oil production was 8,166 Bbls/d as compared to 6,338 Bbls/d in the year-ago period